1. Field of the Invention
This invention relates to the hydraulic fracturing of subterranean formations. In one aspect, the invention relates to a method for degrading polymer residue in a hydraulically induced fracture in subterranean formations.
2. Description of the Prior Art
Hydraulic fracturing has been widely used as a means for improving the rates at which fluids can be injected into or withdrawn from subterranean formations surrounding oil wells and similar boreholes. The methods employed normally involve the injection of a viscous fracturing fluid having a low fluid loss value into the well at a rate sufficient to generate a fracture in the exposed formation, the introduction of fluid containing suspended propping agent particles into the resultant fracture, and the subsequent shutting in of the well until the formation is closed on the injected particles. This results in the formation of a vertical, high-conductivity channels through which fluids can thereafter be injected or produced. The conductivity obtained is a function of the fracture dimensions and the permeability of the bed of propping agent particles within the fracture.
In order to generate the fracture of sufficient length, height, and width and to carry the propping agent particles into the fracture, it is necessary for the fluid to have relatively high viscosity. This viscosity in aqueous liquids is provided by the addition of polymers. Following the treatment of the well, it is desirable to return the aqueous liquid to its low viscosity state, thereby permitting the fracturing fluid and polymer to be removed from the formation and the propped fracture. The highly viscous liquid if left in the fracture would impede the production of formation fluids through the propped fracture. Moreover, the residue of the polymer on the fracture face and in the pores of the propped fracture would significantly reduce fluid permeability therethrough.
To avoid these undersirable after effects of the polymer and polymer residue, it is now common practice to employ in the fracturing fluid chemicals ("breakers") which degrade the polymers U.S. Pat. No. 4,741,401 discloses a number of oxidizing agents contained in capsules for breaking the fracture fluid. U.S. Pat. No. 3,938,594 discloses the use of sodium hypochlorite solution, acid, micellar solutions, and surfactants for degrading the fracturing fluid polymers.
As described in detail in SPE Paper 18862, published Mar. 13-14, 1989, some breakers in fracturing fluids for shallow low temperature (100.degree. F.) treatments are satisfactory for certain polymer gels. This paper further confirms that certain conventional breakers are not effective in fluids gelled with polymers crosslinked with organometallic compounds. For deep, high temperature (175.degree. F. and above) wells, polymers crosslinked with organometallic compounds are generally employed as aqueous viscosifiers. The organometallic crosslinkers were developed for high temperature service exhibiting excellent stability up to about 350.degree. F. Other crosslinkers, such as borate compounds, have an upper temperature limit of about 140.degree. F.
As described in the above SPE Paper, the conventional breakers are not particularly effective with organometallic crosslinked polymers. Moreover, in deep high temperature wells, particularly wells at temperatures in excess of 200.degree. F., breakers cannot generally be used because they tend to degrade the polymer prior to completion of fracture generation phase of the operation.
In these type of wells, clean up of the propped fracture and fracture walls relies on flowing formation fluids therethrough, and may require several months. Acid solutions or other materials sometimes are injected into the propped fracture to assist in polymer degradation. However, these treatments carried out at matrix rates generally results in expending the acid or other compound in the near well bore region (within 10 feet) thereby preventing deep penetration of the active chemical into the fracture.
As demonstrated by the above publications, there is a need for an effective, low cost means for degrading or dissolving polymers in gelled fracturing fluids for deep, high temperature treatments.
As described in detail herein, the present invention involves the use of chlorine dioxide in degrading crosslinked polymers used in high temperature fracturing fluids thereby assisting or effecting cleanup of the fracture. Chlorine dioxide has been proposed for use in a number of oxidizing applications including producing and injection well treatments. For example, Canadian Pat. No. 1,207,269 discloses the use of chlorine dioxide in the separation of oil and water in oil field producing operations. The chlorine dioxide serves as a multifunctional chemical including prevention of sludge and scale, and a biocide for certain compounds in the produced fluid. U.K. Patent Application No. 2170220A also discloses the use of chlorine dioxide in the treatment of wells. In this Application, the chlorine dioxide is added to the produced fluids and serves as a scavenger for hydrogen sulfide. Finally, PCT Application International Publication No. W085/01722 discloses the use of chlorine dioxide in the treatment of produced fluids to eliminate sulfide at oil water interphases. These prior uses of chlorine dioxide have been restricted to produced fluids.
Chlorine dioxide has also been used to degrade polymer in polymer flooding injection wells. In this application, the chlorine dioxide treatment is on noncrosslinked polymers, and effective only in the well perforations and near wellbore region (within 10 feet). Polymer solutions used in polymer flooding are generally dilute solutions containing much less polymer than in fracturing fluids.